The Federal Energy Regulatory Commission on Thursday conditionally accepted the interregional transmission planning and cost allocation proposals by ISO-NE, NYISO and PJM (ER13-1957et al), completing the commission’s initial review of all of the interregional compliance filings required under Order 1000.
FERC found that the three regions complied with its requirement that neighboring transmission planning regions propose a common interregional cost allocation method by agreeing on the use of an avoided-cost method. As permitted by Order 1000, they proposed to apply their avoided-cost allocation to all selected interregional transmission facilities, rather than having separate interregional cost allocation methods for different types of interregional projects.
FERC said the filing conformed to its requirement that interregional cost allocation methods address regional reliability and economic needs as well as transmission needs driven by public policy requirements.
The commission previously ruled that an avoided-cost method was not permissible as the sole cost allocation method for regional transmission projects because it would “not allocate costs in a manner that is at least roughly commensurate with estimated benefits because it does not adequately assess the potential benefits provided by that transmission facility.”
However, it concluded that an avoided-cost only method is permissible for interregional transmission.
“We find that the interplay between the regional transmission planning and interregional coordination requirements of Order No. 1000 address, at the interregional level, the commission’s concerns regarding use of the avoided-cost only method at the regional level,” it wrote.
The commission rejected avoided-cost-only allocation for regional projects because a regional facility that resulted in a more cost-effective transmission solution than what was included in the roll-up of local transmission plans would not be eligible for regional cost allocation if there was no transmission facility in the local transmission plans that it would displace.
In contrast, the commission said it believed “there will be regional transmission facilities identified in the regional transmission planning process that are needed to meet transmission needs driven by reliability, economic and/or public policy requirements that potential interregional transmission facilities may displace.”
The filing updated the Northeastern Protocol, which the three regions adopted in 2004 to facilitate the exchange of information and establish a committee structure for the coordination of interregional planning. The Joint ISO/RTO Planning Committee, comprised of staff representatives from the regions, will be charged with evaluating interregional transmission solutions with input from the Interregional Planning Stakeholder Advisory Committee, which is open to stakeholders.
The commission required the regions to make only minor ministerial changes in compliance filings due in 60 days.
GROTON, Conn. — Robert Ethier has a dream: A day when ISO-NE no longer needs constant stakeholder meetings to tweak its market rules.
Ethier
“We’ll know when we’ve hit on the right market design when we don’t need to make changes to accommodate the changes in the fundamentals,” Ethier, vice president of market operations for ISO-NE, said during a panel discussion at the New England Energy Conference and Exposition last week. “A good, stable, robust market design should adapt to pretty much whatever you can throw at it.”
Ethier said that although New England’s market has work to do to improve demand-side response and integrate the dispatch of wind, it has made progress over the last decade.
“The market is being driven much more by the fundamentals and by policy than by market design. … These markets are really being driven by the larger forces that are changing our economy — changes in fuel prices, changes in technology, changes in policy needs and desires. And that’s really what ought to be driving the markets. It shouldn’t be the market design that’s dominating the discussion.
“I hesitate to say this but I almost think we can see the day when the rate of change in the markets really decreases because the markets have the flexibility they need to react to whatever gets thrown at them,” he said.
GROTON, Conn. — Electric retailers have made progress in moving away from the cutthroat price competition that shaved margins, but restrictions on billing and metering and “organizational inertia” continue to be challenges, a panel told the New England Energy Conference and Exposition last week.
Cullen Hay, general manager of Direct Energy’s residential operations in the Northeast and Midwest, said his company used acquisitions to grow in the past, as it joined other electric retailers in seeking price-conscious customers even as their costs went up. Power suppliers have fewer barriers to prevent customer attrition than cable TV suppliers, telecommunication companies or banks, he said.
“We all kind of lived under the same mantra that as one customer came in the front door, one customer would walk out the back door,” he said.
Over the last three years, however, electric retailers have begun to increase their customer engagement by offering additional services such as home warranties and rooftop solar, he said. “These are not gimmicks. These are the value-added things that the telecom industry found successful when they were handed a deregulated market,” he said.
“The new wave of the industry is knowledge …. Our mission statement is getting our consumers the information they need to make really intelligent decisions. And that goes with consumption-reduction tools like [the] Nest [thermostat] and online portals that allows them to see what their consumption looks like, what their community’s consumption patterns look like” to identify inefficient appliances and make informed decisions.
“That’s the retail, residential industry in the next five years. And it’s already happening.”
Progress, Challenges in Pursuit of C&I Customers
High capacity and transmission costs in regions such as PJM and New England are leading more commercial and industrial customers to welcome companies offering to improve efficiency in return for a share of the cost savings, said Dean Musser, CEO of Tangent Energy Solutions.
“The power customers [are] out there pushing and pushing for ways to innovate. And it’s up to us in this industry to capture that innovation,” he said.
Michael Volpe, who heads SunEdison’s distributed generation business in PJM, said electric retailers could be doing better among C&I customers if not for “organizational inertia.”
“In my experience most energy buyers have a lot of technical acumen but are hesitant to pursue things that they may perceive to be risky due to the long-term nature” of the payback, he said.
The choice, he said, is “getting into the offices of the CFO and sharing how the energy opportunity set has broadened [or] giving the power [to lower-ranking employees] to promote it up” the corporate chain.
Smart Grid Unfulfilled
Musser said the industry and its customers are not getting the full benefits of the billions invested in smart meters.
Philadelphia’s PECO Energy has smart meters for every C&I customer, he said. “But the data is not available until a day later. And if you want a pulse to get the data right away, [it costs] $1,800 and it’s going to take six months.
“That little pulse is two wires coming out of the meter that will enable this … customer to have real-time data every 15 minutes so they can see their consumption and take advantage of all the new products. … But if you’re looking at it a day late that doesn’t help at all.
“Some utilities are adopting methods where there’s free pulses now to get customer adoption. But across the U.S. it’s all over the board for what it costs and how long it takes to get a pulse out of a utility meter,” he said.
Itemized Bills
Hay said limits on itemized bills also are hurting efforts to educate customers about the value of options available to them.
Hay
“Customers may not read direct mail pieces and they may not read their email. But they will look at their bill,” he said. “We are limited to the number of line items we have and the amount of information a supplier like us [can provide]. A more engaged customer is going to be interested in the whole product catalog. We have to find a way to give them that information.”
Because of those limitations, Hay said, his company would like to be the ones sending the bills instead of the distribution utility.
“We are pushing for supplier-consolidated billing with any utility in the U.S. market that will allow us to do so. We are pushing it as part of the [New York] REV program.
“It’s going to have costs associated with it, but we’re prepared to bear those costs. I believe that the impact to churn and the impact to customer attrition that comes from us not having that direct relationship will far exceed whatever cost structure we have to take on.”
The Delaware Public Service Commission on Tuesday unanimously approved Exelon’s $6.8 billion acquisition of Pepco Holdings Inc.
“There is a whole list of very positive things in this agreement,” Chairman Dallas Winslow toldThe News Journal.
The commission had delayed making its decision earlier this month when it learned that the Maryland Public Service Commission was going to make its decision soon (see below). Commission staff had argued that Maryland’s decision would be helpful, as their settlement with Exelon and Pepco contains a “most favored nation” clause, assuring that Delaware receives the same benefits as other states in the deal.
The commission has yet to make a formal order that reflects the balancing of benefits and did not say when it would do so. The approval leaves D.C. as the only holdout on a decision. The deal has been approved by the Federal Energy Regulatory Commission as well as regulators in New Jersey and in Virginia.
Maryland Approves with 3-2 Vote
The Maryland Public Service Commission voted 3-2 to approve the deal on May 15, saying Exelon’s reputation for service excellence was a deciding factor.
It conditioned the deal on higher reliability standards, $100 rate credits for residential customers and $43.2 million in energy efficiency programs in Montgomery and Prince George’s counties.
Voting in support were Chairman Kevin Hughes and Commissioners Kelly Speakes-Backman and Lawrence Brenner, who noted that Exelon ranked in the top-quartile of reliability metrics, while PHI has lagged.
“Simply put, the evidence demonstrates that Delmarva and Pepco will be better utilities because of the merger,” they said in the order released Friday, which included 46 conditions. “Exelon has demonstrated that it knows how to run electric and gas distribution companies; indeed it is nationally recognized for its standards of excellence.”
Voting against the deal were Commissioners Harold Williams and Anne Hoskins. “The merger will impose substantial competitive harm to Maryland’s electricity market by eliminating across-the fence competition, silencing PHI’s unique non-generation voice, and chilling innovation in new energy-related technologies and products,” they said in a 51-page dissent. Exelon still needs to win the approval of Delaware and D.C. to close the deal.
The approval revises certain provisions of a settlement Exelon had reached in March with Montgomery and Prince George’s, in which the corporation agreed to pay a one-time $50 rate credit to each residential customer of Pepco’s two utilities in the state, Delmarva Power & Light and Potomac Electric Power Co. (PEPCO). Exelon had also agreed to invest $57.6 million in energy efficiency. (See Exelon, Pepco Ink Deal with Md. Counties, but Critics Stand Firm.)
The commission also required Exelon to:
Develop 15 MW of solar generation by the end of 2018 — 5 MW in Montgomery County, 5 MW in Prince George’s County and 5 MW in the Delmarva service territory.
Establish a $14.4 million Green Sustainability Fund — $8.4 million for Montgomery and $6 million for Prince George’s — for the counties to fund solar, energy storage and other distributed generation projects.
Exceed Pepco’s level of charitable giving of $656,000 annually for at least 10 years.
Remain a part of PJM at least until the end of 2024.
Develop a pilot program for recreational and transportation use by residents of Pepco’s transmission right-of-ways.
Exelon and Pepco have until May 26 to accept the commission’s conditions. In a statement, Exelon CEO Chris Crane said the company was pleased with the decision and that the commission had recognized its reliability marks, but that the conditions in the order would be “challenging.”
“It poses some stringent conditions that will be difficult to fulfill, but all of us at Exelon accept the challenge and commit to proving ourselves in an expanded role in Maryland,” Crane said.
Critics Disappointed
Commissioners Williams and Hoskins dissented, echoing criticism that has been levied at Exelon throughout the proceeding.
“Maryland will lose its wires-only electric utilities, Pepco and Delmarva, which will be purchased by an energy conglomerate concerned with protecting its vast fleet of electric power plants, from which it derives most of its revenue,” they said. “Exelon’s economic interests to shield that fleet from emerging distributed energy technologies and other competitive threats are inherently misaligned with the interests of the customers of Pepco and Delmarva, who are predominantly concerned with efficient, cost-effective and reliable electric service.”
They also noted that the Green Sustainable Fund would not benefit Delmarva Power’s territory on the state’s Eastern Shore.
While Montgomery County Executive Ike Leggett had reached the county’s settlement with Exelon, the County Council unanimously passed a resolution saying the settlement didn’t go far enough to protect ratepayers and encourage renewable energy. Councilmember Roger Berliner, an energy attorney who spearheaded the resolution, said he was “deeply disappointed with the decision.”
“Exelon has a proven track record of favoring its own nuclear generation holdings over renewable technologies like solar and wind,” Berliner said. “This merger poses an unacceptable threat to both ratepayers and our environment.”
Berliner did acknowledge the beneficial conditions of the approval. He said that he has been “knocking on Pepco’s doors” to open up their rights-of-way, but the utility “stiff-armed us for years.”
The order includes a concession Berliner had sought — a Montgomery County “green bank” through which the county will use Exelon contributions to “leverage” investment in clean energy and energy-efficiency technologies.
But Berliner lamented the fact that these breakthroughs were achieved through the acquisition process, and by the level of Exelon’s commitment to renewable energy, which he said, “just didn’t go far enough.”
Environmentalists agreed.
“We are disappointed by today’s decision, which comes as a blow to the future of clean energy in Maryland,” said David Smedick of the Sierra Club. “The meager conditions added by the commission do not come close to mitigating the harms that the merger will cause to Marylanders.”
Maryland Attorney General Brian E. Frosh also blasted the order.
“Today is a bad day for consumers, and a great day for monopolies,” he said in a statement. “This merger — which the PSC approved by the slimmest of margins — would create a company controlling service to 80% of Maryland’s electric consumers, with the incentive and ability to stifle competition and suppress innovation. The harm to customers under this arrangement are obvious and substantial.”
PJM Independent Market Monitor Joe Bowring was disappointed by the ruling.
“They didn’t accept our conditions, so we didn’t think they did enough,” Bowring said. “What we would have liked was for Maryland to accept the conditions we proposed,” which the Monitor has proposed to all of the involved entities.
One to Go
Opposition to the Exelon-Pepco marriage continued to grow last week in D.C., where regulators may make a decision as soon as May 27, when the record closes.
Four D.C. Council members and more than half of the District’s 42 local advisory neighborhood commissioners — some of whom rallied on the steps of the Wilson Building Tuesday — are lobbying Mayor Muriel Bowser to take a stand against the transaction, though she doesn’t have an official role in the decision.
Councilman David Grosso submitted a May 12 letter to the D.C. PSC urging the board to reject the deal. The following day, People’s Counsel Sandra Mattavous-Frye filed a brief advising the PSC against the takeover.
“While this merger provides a wealth of benefits for Exelon and PHI’s shareholders, it exposes District of Columbia ratepayers to a number of unnecessary risks,” she said. “I am primarily concerned that Exelon has failed to commit to meeting established reliability standards, that any financial benefit to consumers will be erased with the first rate case and that the major decisions impacting the city’s electrical infrastructure will be made by executives in Chicago.
“As it regards the city, I am concerned that the success the District has achieved in the area of deploying renewables will be compromised by Exelon’s corporate philosophy that favors generation companies. Moreover, I have no confidence in Exelon’s ability to deliver on the promise of more jobs.”
A Year in the Making
The deal, announced last April as an all-cash transaction, has been more than a year in the making. If the deal is approved, it will create the Mid-Atlantic’s largest electric and gas utility.
Exelon is familiar with mergers. The company is the product of the 2000 pairing of Philadelphia’s PECO Energy and Chicago’s Commonwealth Edison. In 2012, it acquired Baltimore’s Constellation Energy.
It hasn’t always been successful in its deal making, however.
Exelon dropped a proposed merger with Public Service Enterprise Group in 2006, and had its overtures spurned by PPL in 1995 and NRG in 2009.
Exelon has said the deal will boost its customer count to almost 9.8 million from 7.8 million and increase its rate base to almost $26 billion from $19 billion.
Exelon hopes to close the deal by the end of the year.
WASHINGTON — Despite changing its meeting date to avoid threats of mass demonstrations next week, the Federal Energy Regulatory Commission couldn’t avoid another protest drama Thursday.
FERC instituted a new policy that forced all non-employees — lawyers, lobbyists, reporters and protesters — through a lengthier and more rigorous-than-normal security screening that included photographs. After receiving a paper ID badge and going through a metal detector, the known protestors were directed left, while the others went right to the escalator to the second-floor Commission Meeting Room.
When the protestors were informed they would be quarantined in a commission hearing room where they could watch video of the meeting, they began chanting “Shut FERC down!” (See video.) While organizers claimed the protesters numbered three dozen, only about 15 appeared in a video the group shot after being ejected.
Suits, not T-shirts
Among them was Ted Glick, national campaign coordinator at the Chesapeake Climate Action Network, who wore a suit rather than the red T-shirt he and other protesters had worn in previous meetings. (See Protests Continue — on Camera — at FERC.)
About 20 minutes into the meeting, as the commission was discussing a ruling on an Order 1000 compliance filing, the protesters apparently exited the hearing room. The protesters’ chants were audible — if not discernible — in the meeting room until they were escorted out of the building.
FERC Chairman Norman Bay joked, “I hope the protesters haven’t moved from pipelines to Order 1000,” prompting laughter.
But at least three protesters slipped the dragnet and were able to make brief statements before being escorted out.
PennEast Pipeline
The first two, Patty Cronheim of Hopewell Township, N.J., and Angela Switzer of Delaware Township, N.J., stood up to protest the proposed PennEast Pipeline. The 36-inch pipeline would deliver about 1 billion cubic feet of gas per day from Luzerne County, Pa., to Transco’s pipeline interconnection in Mercer County, N.J., 108 miles away.
“You’re destroying lives, you’re abusing eminent domain,” Switzer said before being led out of the meeting. “This is corporate greed over public need.”
Switzer said afterward she is concerned the pipeline, which would cross her 60-acre farm, could result in contamination of her water wells. “I live in an arsenic-rich zone and there’s a chance when they drill through the bedrock they’re going to release arsenic into my wells,” she said. “… FERC is not listening to us.”
The backers of the project — AGL Resources; NJR Pipeline Company; PSEG Power; South Jersey Industries; Spectra Energy Partners; and UGI Energy Services — are hoping for FERC approval in 2016.
A third protester, Maggie Henry, of Bessemer in Western Pennsylvania, stood up as the meeting was adjourned, shouting “In the shale plays of Pennsylvania, you are killing people!”
In a press conference afterward, Bay turned serious, reading a statement in which he criticized the repeated meeting interruptions as “disrespectful” and ineffective.
“I respect the First Amendment rights of the protesters and I want to hear their views. But there are ways to do that and there are ways not to do that,” he said. “The way not to do it is to disrupt our proceedings. In my view the disruptions are disrespectful, they violate the law [and] they can pose public security concerns. They often violate the ex parte rule. They prevent us from doing our work and it’s a turnoff. It’s ineffective and unpersuasive as a matter of advocacy.”
Bay also noted that the commission does not regulate the production of natural gas. “If someone is upset with fracking, they should probably talk to the states. If I had any advice for the protesters it would be this: tell them to reconsider what they’re doing and I would urge them to stop disrupting our meetings.”
FERC acknowledged that it had rescheduled the meeting at the recommendation of Federal Protective Services, which wanted to avoid demonstrations planned for the week of May 21-29, including the scheduled May 21 session. Beyond Extreme Energy, the organization that has been coordinating the FERC protests, had said it is hoping to attract more than 500 demonstrators to FERC during the week.
In November, about 100 climate change protesters blockaded FERC headquarters, snarling traffic on First St. N.E. About 25 were arrested.
More change is coming to the Federal Energy Regulatory Commission, as Commissioner Philip Moeller announced last week that he won’t be returning for a third term.
Patrick McCormick sits left of Sen. Lisa Murkowski during Norman Bay and Cheryl LaFleur’s confirmation hearing last year.
News of Moeller’s departure set off one of Washington’s favorite parlor games: guessing his replacement. Sources have tabbed Patrick McCormick III, chief counsel for Senate Energy and Natural Resources Committee Chairman Lisa Murkowski (R-Alaska), as the likely nominee.
Murkowski named McCormick as her chief counsel in 2013. He joined Murkowski’s staff as special counsel in April 2011 from Hunton & Williams, where he was a partner and led the firm’s regulated markets and energy infrastructure practice. Among McCormick’s law clients were Xcel Energy and coal giant Peabody Energy.
He was also registered as a lobbyist for FirstEnergy and the CCS Alliance, which promotes carbon capture and sequestration.
McCormick took a big pay cut to join the committee. He reported earning $567,000 in 2010 and $374,000 through April 15, 2011, at Hunton & Williams. His initial salary when he joined the Senate committee staff was about $81,000.
Before joining Hunton & Williams in 2005, McCormick was the managing partner for the Washington office of Balch & Bingham, longtime counsel for Southern Co.
McCormick also served as a deputy assistant general counsel for FERC, where he dealt with electric rates and corporate regulation, and in the law and governmental affairs departments of Potomac Electric Power Co. (PEPCO). He earned a Bachelor of Arts in history at Wheeling Jesuit University in 1977 and his law degree from Catholic University of America in 1984.
McCormick did not respond to a request for comment Monday.
If he is confirmed, and Murkowski has her way, McCormick could be implementing the first major energy legislation since the Energy Policy Act of 2005.
On May 7, Murkowski introduced 17 legislative proposals that she said would modernize the nation’s energy policies, improve infrastructure and speed review of natural gas pipelines on federal lands.
“America’s energy landscape has undergone a dramatic change since Congress last acted on comprehensive energy legislation. Our domestic energy supply has gone from scarce to abundant,” she said. “Our energy renaissance underscores the need to modernize America’s energy policies.”
Moeller to Remain Pending Replacement
Moeller, whose term expires June 30, said he will remain on the commission until a replacement is sworn in. A Republican, Moeller joined the panel in 2006.
“It’s been an honor and a privilege to serve on the commission every single day since I joined the commission in July 2006,” he said in a statement. “I send thanks to President Bush and President Obama for nominating me, as well as the members of the United States Senate who unanimously confirmed me to both terms.”
Moeller’s departure comes as the commission is adjusting to a new chairman, Norman Bay, who replaced Cheryl LaFleur in April. (See LaFleur Chairmanship Ending; Bay to Take Gavel.) The newest commissioner, Colette Honorable, joined the panel in December.
McCormick’s arrival could make for some interesting interpersonal dynamics on the commission given Murkowski’s cool reception to Bay’s nomination. (See GOP Remains Skeptical on Bay Nomination.)
Moeller’s departure means he won’t have a chance to become chairman if a Republican wins the White House in 2016.
Before joining the commission, he worked from 1997 through 2000 as an energy policy adviser to U.S. Sen. Slade Gorton (R-Wash.). Before joining Gorton’s staff, he was the staff coordinator for the Washington State Senate Committee on Energy, Utilities and Telecommunications. Before becoming a commissioner, he headed the D.C. office of Alliant Energy and worked in the D.C. office of Calpine.
WASHINGTON — In the 11 months since the Environmental Protection Agency proposed its Clean Power Plan, the idea that the final rule should include a reliability “safety valve” has become an article of faith among utility, state and RTO officials.
Count former state regulator Sue Tierney among the nonbelievers.
“I don’t think a reliability safety valve is needed because … we have those mechanisms in place today,” Tierney told a Bipartisan Policy Center forum Friday. “We have reliability-must-run contracts. We have ways to address voltage support. We have ways to address inertia. … We will not allow a plant to retire if it’s needed for reliability purposes.”
John Moore, NRDC
Tierney, senior advisor for the Analysis Group, and John Moore, senior attorney for the Natural Resources Defense Council’s Sustainable FERC Project, were in the minority in cautioning against a mechanism for providing relief from the EPA’s carbon emission rule.
Indicating their support at the forum were Gerry Cauley, CEO of the North American Electric Reliability Corp.; PPL CEO William Spence; Michael Dowd, director of the Virginia Department of Environmental Quality’s air division; James W. Gardner, vice chairman of the Kentucky Public Service Commission; Craig Glazer, PJM’s vice president for federal government policy; and John Novak, the National Rural Electric Cooperative Association’s executive director for environmental issues.
Federal Energy Regulatory Commissioner Colette Honorable mostly listened and asked questions.
Jason Grumet, BPC
BPC President Jason Grumet said the forum was intended as “a constructive, messy, complicated conversation.” He opened the four-hour discussion by declaring what was out of bounds: “We are not going to debate the interim [EPA] targets. We are not going to be debating the legality of the rule. We’re not going to be debating the existential question of whether climate change exists,” he said.
Tierney began her comments by remarking that preparations for EPA’s Mercury and Air Toxics Standards also prompted apocalyptic warnings. Yet when the rule took effect April 16 — albeit, with a reliability safety valve included — the lights did not go out, she said.
“Business as usual is not assuming that the problems are going to go away,” she said. “Business as usual in this industry is making sure reliability is addressed all the time.”
Fear of Complacency
Tierney and Moore spent much of their time debating NERC’s Cauley and PJM’s Glazer.
Gerry Cauley, NERC
“One thing I’d like to challenge is assertions that because the grid and the utility industry [have] been resilient in the past and resolved all problems … [they] will continue to do so,” Cauley said. “We don’t work that way. If a power company operates on that presumption we go get ‘em and fine them a million dollars a day. Because you can’t go off into unknown areas and not have a well-planned, well-operated system.”
Glazer spoke on behalf of the ISO/RTO Council, which included a detailed reliability safety valve proposal in its comments to EPA. “If we do this right, Sue is right, we shouldn’t need the reliability safety valve. But boy it is a good thing in our view to have.”
Spence, representing the investor-owned utilities of the Edison Electric Institute, agreed. “We’re not asking for a free pass,” he said. “We’re just saying if we get ourselves into a situation where we need to do something, [EPA can provide relief from compliance]. I think that’s a reasonable ask.”
William Spence, PPL
“There will be nothing that will derail the Clean Power Plan quicker than having a reliability event,” he added. “So I would suggest [to] people who really want to see [EPA’s 30% emissions reduction] pushed across the finish line: We ought to have all the tools that we possibly can have.”
Novak said the mechanism could be needed if Virginia lost the North Anna nuclear plant. “What if for some reason [North] Anna goes down for several years — or like San Onofre in California, it goes down forever?” he asked. “Are there going to be sufficient offsets to make up for 1,000 MW or more of non-emitting generation? How long will it take to get that extra … energy?”
Dowd said he was concerned about relying on existing law and mechanisms to ensure reliability.
“The question of whether reliability trumps environment has not been established,” he said. “… The courts have not decided that.”
Undermining Markets
Tierney said the flexibility of the proposed rule — which would allow states to engage in interstate emissions trading and to lower emissions through energy efficiency, renewables and low-carbon fuels — provides ways to balance reliability and compliance.
Susan Tierney, The Analysis Group
Tierney said the IRC’s proposal could result in an “administrative nightmare” and undermine the discipline needed to develop market-based compliance programs.
“Just about every [concern] that I’m hearing about could be solved with market-based approaches,” she said. “The biggest thing that will be an impediment to the development of carbon markets would be a safety valve that creates the ability to leak carbon into the atmosphere.”
Glazer responded by quoting former Defense Secretary Donald Rumsfeld’s quote: “You go to war with the army you have, not the army you wish you had.”
“The reality is we are not going into this with a mandatory, nationwide [carbon] market,” he said. “This is not Waxman-Markey,” the cap-and-trade bill that failed to win Senate passage in 2010.
Cauley acknowledged that electricity markets are resilient. “But they’re not infallible, because they are limited by gas supply [and] by resources that do get retired.
“Do I want to bet the future of grid reliability five years from now, 10 years from now on a robust carbon market? I don’t think we’ve seen that yet and I don’t know that there’s any assurance that that will materialize,” he said.
No ‘License to Steal’
Craig Glazer, PJM, with piece of transmission tower
Glazer said the IRC’s proposal was designed with a high burden of proof and only time-limited relief to ensure it didn’t become a “license to steal.” It would require independent verification that there is a reliability problem that can’t be addressed through carbon offsets.
“If somebody can just run into the governor’s office and get a five-year, 10-year extension, this is going to be a farce,” he acknowledged.
Moore said any increased emissions resulting from such relief should be offset by reductions elsewhere.
He recalled the fight over GenOn Energy Management’s coal-fired Potomac River Generating Station outside D.C., which shut down in September 2012 under pressure from environmentalists and public officials.
“Because of the ex parte rules … I couldn’t call Joe McClellan, who was [FERC’s] reliability coordinator. We couldn’t have him at meetings. FERC became irrelevant to the process,” Glazer said. “So I implore you to find creative” alternatives.
Sitting to Glazer’s left, Commissioner Honorable nodded. “Noted,” she said.
VALLEY FORGE, Pa. — PJM provided more details last week on the April 21-22 transmission outage that resulted in the dispatch of demand response in the Erie area.
PJM’s Joe Ciabattoni told the Operating Committee that early on April 21, one of the three feeds into the Erie area, located in the PENELEC zone, was on a scheduled outage when a circuit breaker failed, taking one of the remaining paths out of service.
“That resulted in severe low voltage in a load pocket of about 200 MW,” he said. “If we had lost a third feed in the area, we would have lost that load pocket.” Ciabattoni noted at last week’s Market Implementation Committee meeting, where the matter also was discussed, that there always are voltage concerns in that area when there are planned or unplanned outages, and that an upgrade is included in next year’s Regional Transmission Expansion Plan.
When a workaround to bypass the breaker did not come to pass, PJM issued a PENELEC zone-wide voluntary call for DR to alleviate some of the voltage violations and implemented a switching solution, he said, estimating the DR available that evening at 130 MW.
“Going through the midnight period, we lost some generation in the area, which further aggravated the situation,” Ciabattoni said, so a voluntary call for DR again was made the following morning, when an estimated 73 MW was available. Because the outage occurred during a non-compliance period, all of the response was voluntary.
A sub-zonal call for DR was not made, he told the MIC, because it would have required a prior-day’s notice.
The event sparked the creation of two new closed-loop pricing interfaces in order to capture the DR dispatch in LMPs rather than in uplift — ERIE-PN, which is within the PENELEC zone, and the entire zone itself.
However, Stu Bresler, PJM vice president of market operations, told the MIC that PJM would not have let DR set prices for the full zone because the issue was isolated to the Erie area.
Black Start Service Undergoes Annual Revenue Recalculation
Black start generators are in the process of requesting changes to their annual revenue requirements, reflecting adjustments to net cost of new entry, operations and maintenance and fuel storage costs.
All combustion turbines and combined cycles, including black start units, are required to make changes to their accounting of maintenance expenses, said Thomas Hauske, senior lead engineer.
Unit owners and the Independent Market Monitor have until Thursday to agree on changes. PJM must accept or reject submitted values by May 27. The new rates take effect in June.
Curtailment service providers registered 6,700 MW of pre-emergency DR and 1,550 MW of emergency DR as of April 30. Lead times break down as follows: Quick (30 minutes), 5,600 MW; Short (60 minutes), 350 MW; and Long (120 minutes), 2,300 MW. There are 6,000 MW of Limited DR (June- September); 2,100 MW of Extended Summer (May- October); and 150 MW of Annual DR. The figures will not be finalized until May 31.
The products are always called as a group unless they are out of season or they have been called too many times and PJM wants to save some Limited DR calls for later in the summer.
PJM has automated its dispatch of DR through its emergency procedure postings.
VALLEY FORGE, Pa. — The most likely dates for the 2018/19 Base Residual Auction to commence are Aug. 3 or Aug. 10, Jeff Bastian, manager of capacity market operations, told the Market Implementation Committee last week.
The timing will be determined by when the Federal Energy Regulatory Commission rules on PJM’s Capacity Performance proposal, which should be no later than June 9, assuming the commission acts 60 days from PJM’s April 10 response to FERC’s deficiency letter. (See PJM Responds to FERC Queries on Capacity Performance, Requests Approval.)
Bastian said PJM plans to announce a firm date for the auction, as well as deadlines for updates to market participant pre-auction submissions, shortly after FERC hands down its decision. PJM proposes using Aug. 3 if FERC rules on or before May 26, and Aug. 10 for an announcement after that date.
There are two scenarios, he said: Either the auction will be conducted according to PJM’s proposal, with or without FERC adjustments, or it will operate under the status quo.
Even if the new capacity product is denied and the auction runs under current rules, Bastian said, PJM believes it would be in everyone’s interest to utilize the 75 days allowed in its waiver to delay the auction, which generally is required to be held in May. (See FERC OKs PJM Request to Delay Capacity Auction.)
The Capacity Performance proposal (ER15-623) was conceived to increase reliability by implementing a “no excuses” policy that is expected to result in more incentives for over-performing participants and higher penalties for non-performers.
Bastian noted that an Aug. 3 auction date might necessitate an adjustment to the 2016/17 second incremental auction to avoid overlap.
PJM Member in Default, to be Terminated
PJM will seek to terminate the membership of Intergrid Mideast Group after it was declared in default for failing to honor collateral and payment obligations, CFO Suzanne Daugherty told the MIC.
Intergrid has accumulated three defaults within 12 months, and after the first one, its transaction rights were suspended. Now, PJM will be submitting a request with FERC to permanently cancel its membership, regardless of whether the defaults are rectified.
Intergrid, primarily a holder of financial transmission rights, paid its invoices through April 24. Its invoice due May 1 was fulfilled by the collateral it had posted with PJM, as will be the bill due May 8. That will leave $250,000 in remaining cash collateral.
PJM estimates that Intergrid may be liable for up to $2 million in charges on FTRs that expire May 31.
PJM plans to liquidate the FTR positions Intergrid also previously cleared in auctions for the 2015/16, 2016/17 and 2017/18 planning years. The positions for 2015/16 will be offered for sale during the FTR auction that opens this week.
The remaining positions will be offered for sale during the FTR auction that opens in early June.
PJM had no estimate for how much it will cost to liquidate the FTR positions.
Tariff Harmonization Group Offers First New Definition
The Tariff Harmonization Senior Task Force, formed in December to resolve inconsistencies and ambiguities in PJM’s governing documents, brought forward its first proposed change: the definition of PJM Net Assets.
“We thought it would be important to try and clarify what portion of PJM assets would be available for a third-party claim if one were made,” CFO Suzanne Daugherty told the committee. “You all don’t want everything in our financial statement available to a third-party claim.”
At any one time, she said, PJM could be holding roughly $1 billion on behalf of members, she said, but it’s not an asset.
The new definition specifies that PJM’s “Net Assets” will include those reflected in the RTO’s financial statements and not those for which it is acting as a temporary custodian on behalf of its members.
The group is prioritizing about 50 definitions and will next meet May 29.
New PJM Member Community to Debut
PJM will launch a new tool for interacting with members on May 18: the online PJM Member Community.
PJM’s Bill Walker said the new tool was conceived in response to members’ desire for a way to have their concerns acknowledged, track an issue or research topics themselves.
The service will provide the real-time status of a request, live chat, information on invoices and more.
Future enhancements are expected to allow members to initiate a change request, enable electronic signatures and integrate a mobile app.
The portal will be accessed through the “MyPJM” account ID.
VALLEY FORGE, Pa. — Months of debate over whether to create “historic” capacity rights for some unnamed load-serving entities in PJM got a face last week when a small contingent from the Illinois Municipal Electric Agency showed up at a meeting of the Market Implementation Committee to lobby for the changes.
The Tariff amendments would allow LSEs to use generation resources outside of their locational deliverability areas (LDAs) to meet their internal resource requirements if that external capacity agreement was in place before June 1, 2007, when PJM implemented its Reliability Pricing Model. (See Stakeholders Skeptical of PJM Proposal for ‘Historic’ Capacity Transfer Rights.)
Stu Bresler, PJM’s vice president of market operations, who had proposed the change, had not identified any potential beneficiaries, although it was clear one would be IMEA.
In January, IMEA failed to win approval from the Federal Energy Regulatory Commission to continue using capacity resources outside of the Commonwealth Edison LDA to meet its internal resource requirement in serving its Naperville, Ill., load. (See FERC Denies IMEA Request for Extended Waiver on Capacity Obligation.)
Last week, IMEA representatives came to Valley Forge state their case.
“We wanted to put a face on this and give you our answers,” said Troy Fodor, IMEA vice president and general counsel, who was joined by two colleagues.
“From our perspective, we’re not asking for a preference. We got the long-term transmission rights as part of going out and building brand-new plants,” he said. “We believe that since we have the firm long-term transmission rights that the transfer capability is ours. So, to the extent that it’s being taken and allocated out, and we’re getting a higher internal resource requirement, it feels like you’re taking our stuff.”
If it is a preference, he added, it’s one that IMEA feels it has justified by investing “a billion dollars” in plants to deliver load in ComEd.
In an interview after the meeting, Fodor explained the trip. “We need a solution,” he said. “If this process is going to fail, we have to start working at the next step. The reason we’re here is it looked like [talks] were going in the wrong direction.
“We have a good story,” he said. “We think we have a legitimate story.”
Bresler told the committee that historic capacity resources would not exceed the value at which they were initially established — and if the load should decrease, it would never go back up.
Market Monitor Joe Bowring, who has opposed Bresler’s proposal, said he continued to be concerned that the approach is too broad. “We are going to attempt to work with PJM and IMEA to see if there’s a way to come up with a more targeted approach,” he said.
PJM estimates 1,037 MW of historic external resources would qualify under its proposal: 122 MW in the DOM zone, 533 in COMED, 261 in AEP and 121 in DAY.
Bresler said the committee would see a first reading on proposed Tariff changes in June.
FERC found that the three regions complied with its requirement that neighboring transmission planning regions propose a common interregional cost allocation method by agreeing on the use of an avoided-cost method. As permitted by Order 1000, they proposed to apply their avoided-cost allocation to all selected interregional transmission facilities, rather than having separate interregional cost allocation methods for different types of interregional projects.
ill lose its wires-only electric utilities, Pepco and Delmarva, which will be purchased by an energy conglomerate concerned with protecting its vast fleet of electric power plants, from which it derives most of its revenue,” they said. “Exelon’s economic interests to shield that fleet from emerging distributed energy technologies and other competitive threats are inherently misaligned with the interests of the customers of Pepco and Delmarva, who are predominantly concerned with efficient, cost-effective and reliable electric service.”
